EX-99.1 2 d845386dex991.htm EX-99.1

Investor Presentation January 2015 Exhibit 99.1

Statements contained in this presentation that state the company’s or management’s expectations or predictions of the future are forward– looking statements intended to be covered by the safe harbor provisions of the Securities Act of 1933 and the Securities Exchange Act of 1934. The words “believe,” “expect,” “should,” “estimates,” “intend,” and other similar expressions identify forward–looking statements. It is important to note that actual results could differ materially from those projected in such forward–looking statements. For more information concerning factors that could cause actual results to differ from those expressed or forecasted, see Valero’s annual reports on Form 10-K and quarterly reports on Form 10-Q, filed with the Securities and Exchange Commission, and available on Valero’s website at www.valero.com. 2 Safe Harbor Statement

3 Who We Are World’s Largest Independent Refiner Large Logistics Infrastructure with Focus on Growth • • Wholesale Fuels Marketer • • One of North America’s Largest Renewable Fuels Producers • • • 15 refineries, 2.9 million barrels per day (BPD) of high-complexity throughput capacity • Greater than 70% of refining capacity located in U.S. Gulf Coast and Mid-Continent • Approximately 10,000 employees General partner and majority owner of Valero Energy Partners LP (NYSE: VLP), a growth-oriented, fee-based master limited partnership (MLP) Significant inventory of logistics assets within Valero Brands include Valero, Ultramar, Texaco, Shamrock, Diamond Shamrock, and Beacon 11 corn ethanol plants, 1.3 billion gallons per year (85,000 BPD) production capacity Operator and 50% owner of Diamond Green Diesel joint venture – 10,500 BPD renewable diesel production capacity Approximately 7,400 marketing sites in U.S., Canada, United Kingdom, and Ireland

4 Assets Concentrated in Advantaged Locations Refinery Capacities (MBPD) Nelson Index Throughput Crude Oil Corpus Christi 325 205 19.9 Houston 165 90 15.1 Meraux 135 135 10.3 Port Arthur 350 330 12.6 St. Charles 280 190 17.5 Texas City 250 225 11.1 Three Rivers 100 95 12.4 Gulf Coast 1,605 1,270 14.1 Ardmore 90 86 12.1 McKee 170 168 9.5 Memphis 195 180 7.9 Mid-Con 455 434 9.3 Pembroke 270 220 9.7 Quebec City 235 230 7.7 North Atlantic 505 450 8.7 Benicia 170 145 16.1 Wilmington 135 85 15.8 West Coast 305 230 16.0 Total or Avg. 2,870 2,384 12.4

Strategy to Enhance Stockholder Returns Operations Excellence Capital Returns to Stockholders Disciplined Capital Investments Unlocking Asset Value • Demonstrate commitment to safe and reliable operations • Continuously improve our top-tier operating performance • Optimize margins with refining system’s feedstock and product markets flexibility • Disciplined capital allocation • Seek to increase cash returns through dividend growth • Use stock buybacks to reduce shares outstanding and concentrate future value per share • Rigor in capital projects and M&A selection and execution • Invest to grow logistics assets and reduce feedstock costs • Evaluate investments to upgrade natural gas and natural gas liquids • Opportunistically invest in ethanol to maintain high returns • Grow Valero Energy Partners LP and realize value for Valero • Evaluate acceleration of dropdowns and other potential MLP-able earnings streams • Previously unlocked value in retail business via 2013 spinoff to stockholders 5

6 Key Market Trends U.S. and Canadian crude oil, natural gas, and natural gas liquids (NGLs) production growth is providing cost advantages to North American refiners Global refined products demand growth is expected to continue Location-advantaged refiners in U.S. Gulf Coast, Mid-Continent, and Canada benefit from resource advantages and/or export opportunities - Lower crude prices may temporarily constrain production growth rate - Expect lower prices to consumers will drive product demand growth

Production Growth Provides Resource Advantage to North American Refiners Source: DOE (for 2014, data through September) Source: DOE (for 2014, data through September) 7 40 45 50 55 60 65 70 U.S. Natural Gas Production (Bcf/day) 4,500 5,000 5,500 6,000 6,500 7,000 7,500 8,000 8,500 9,000 6,500 7,000 7,500 8,000 8,500 9,000 9,500 10,000 10,500 MBPD MBPD U.S. Crude Oil Production and Imports Imports Production

8 Persistent Focus Drives Results in Safety, Environmental, and Regulatory Compliance (1)Source: U.S. Bureau of Labor Statistics. All 2014 values are estimates. Statistics are for Refining only. Operations Excellence 0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 Personnel Safety Employees Contractors Industry (1) 0.00 0.05 0.10 0.15 0.20 Tier 1 Process Safety 0 5 10 15 20 0 10 20 30 40 Environmental Events Total Air Emissions (U.S. Refineries)

9 Top-Tier Operating Performance through Continuous Improvements 2012 2010 2008 • Reliability drives safe and profitable operations Seven of our refineries are first quartile in mechanical availability • Initiated new reliability programs beginning mid-2000s • Significant gains made in operations benchmarks since 2008 • Personnel committed to excellence 1 st Quartile 2 nd Quartile 3 rd Quartile 4 th Quartile Source: Solomon Associates and Valero Energy, includes Pembroke and Meraux

Sustained high availability and favorable margin environment enable higher capacity utilization rates 10 Reliability Programs and Commercial Optimization Drive Higher Utilization Rates System-wide mechanical availability near 1 st Quartile since 2011 88% 87% 92% 95% 96% 2010 2011 2012 2013 2014 1Q-3Q Valero Refinery Utilization Rates

Optimizing Margins with Feedstock Flexibility in Our Complex Refinery System Range of Flexibility in Valero’s Gulf Coast Region Quarterly Feedstock Mix 2010-2014 • Capability to adjust feedstocks and optimize margins as crude price environment shifts among grades: light, medium, heavy, sweet, sour • Focus on optimization activities • Expect additional light crude flexibility with completion of topper units in progress 35% 34% 28% 23% 9% 26% 20% 12% 12% 4% Avg 30% Avg 26% Avg 20% Avg 18% Avg 6%

• 120 MBPD of combined new capacity successfully started end of 2012 and mid-2013 • Designed to produce high-quality distillates from low-quality feedstocks and natural gas Port Arthur and St. Charles Hydrocrackers Performing Better Than Expected 12 (1) See Appendix for details and assumptions • Approximately half of benefit seen by >4% points increase in margin capture rate • Approximately half of benefit due to 100 MBPD increase in throughput volumes from feedstocks and new gas plant • Realized annual EBITDA estimated at $800 million for trailing 4-quarters 3Q14 • Compares to $780 million implied by disclosed guidance model (1) • Benefits visible in U.S. Gulf Coast region reported results improvement from 4Q12 to 3Q14 (1)

Disciplined Capital Allocation Framework Emphasizes Stockholders Dividend Growth • • Sustaining Capex • • Debt and Cash • • Stock Buybacks • • Growth Capex • Acquisitions • • “Non-Discretionary” “Discretionary” 13 Capital Returns to Stockholders (1) Debt-to-cap ratio based on total debt reduced by $2 billion cash balance, excluding VLP debt and equity Estimate $1.5 billion or lower annual “stay-in- business” spend • Key to safe and reliable operations Focus on sustainability Increase competition for cash flow versus reinvestments (growth capex and acquisitions) Maintain investment grade credit rating Target 20% to 30% debt-to-cap ratio (1) Flexibility to return cash, reduce share count, and manage capital employed Increase competition versus reinvestments Prioritize higher-value, higher-growth, faster- payback opportunities that enhance future returns Evaluate accretion versus stock buybacks Enhance future returns

14 Increasing Focus on Dividends and Stock Buybacks • Regular dividend increases over last three years • Significantly increased stock buybacks in 2013 and 2014 • Accelerated stock buybacks throughout 2014 with 10 million shares bought in 4Q14 • Approximately $2 billion of stock repurchase authorization at end of 3Q14 Given cash return priority, we plan to increase our total payout ratio of earnings over 2014’s level $0.10 $0.15 $0.20 $0.25 $0.30 Dividend Per Share of Valero 1Q 2Q 3Q 4Q $0 $500 $1,000 $1,500 2011 2012 2013 2014 millions Stock Buybacks

15 Advancing Growth Investments While Managing Capital Spending Lower (1) Excludes estimated placeholder for methanol project of $150 million in 2015 and $300 million in 2016 as evaluation remains in progress Disciplined Capital Investment • Focus on logistics growth after 2015 spending to complete crude toppers • Expect nearly all logistics growth investments to be eligible for dropdown into VLP millions $2,900 $2,650 $2,400 $695 $695 $900 $400 $615 $765 $730 $690 $790 $300 $715 $655 2014E 2015E 2016E Logistics Growth Refining, Renewables, & Other Growth Turnarounds & Catalyst Sustaining (1)

• Completed tie-in to pipeline in Childress, TX and secured incremental 40 to 50 MBPD Midland-priced crude as substitute for Cushing-priced crude primarily at the McKee refinery • Expect Diamond Pipeline to supply Memphis refinery via Cushing and start up in 1H17 or earlier • Tanks and vessels to supply crude to Quebec City refinery post-Enbridge Line 9B reversal expected in 1H15 • New Corpus Christi dock commissioned in 3Q14; completion of tanks for crude exports expected in 1H15 16 Logistics Investments Enhance Valero’s Feedstock Flexibility and Export Capability • Purchased 5,320 CPC-1232 railcars; received 3,547 through Nov 2014 • Completed crude unloading facilities at Quebec City, St. Charles, and Port Arthur in 2014 • Benicia crude unloading facility undergoing permitting process Pipelines Tanks, Docks, and Vessels Rail

Crude Topper Investments Very Attractive 17 Estimate $500 million annual EBITDA for combined projects in 2014 price environment • 160 MBPD new topping capacity designed to process up to 50 API domestic sweet crude Lowers feedstock cost by generating 55 MBPD low sulfur resid Increases net throughput capacity by 105 MBPD • Expect startup in 1H16 • Expect 50% IRR on 2014 prices, >25% IRR with Brent and LLS even • Corpus Christi: Estimated $350 MM capex for 70 MBPD capacity • Houston: Estimated $400 MM capex for 90 MBPD capacity Incremental Volume (MBPD) Feeds Eagle Ford crude 160 Low sulfur atmos resid (55) Products LPG 3.3 Propylene 1.3 BTX 0.4 Naphtha (at export prices) 40 Gasoline 12 Jet 39 Diesel 13 Resid (3) Combined Projects Estimates Total investment (1) $750 MM Annual EBITDA contribution (2) $500 MM Unlevered IRR on total spend (2) 50% See Appendix for assumptions. (1) Excluding interest and overhead allocation (2) Estimates based on 2014 prices through Dec 9; EBITDA = operating income before deduction for depreciation and amortization expense

Key Natural Gas and NGLs Upgrading Investments 18 Hydrocracker Expansions Evaluating Methanol Plant at St. Charles Evaluating Houston Alkylation Unit • 1.6 – 1.7 million tonnes per year production (36 – 38 MBPD) • Leverages existing assets to lower capital requirement compared to grassroots facility • In evaluation; estimated capital cost and project economics remain in development • Expect investment decision in 2Q15; startup in 2018 if approved • 12.5 MBPD capacity • Upgrades low-cost NGLs to premium-priced alkylate • In evaluation; estimated capital cost and project economics remain in development • Expect investment decision in 2015; startup in 2017 if approved • Increase distillate yield partially from hydrogen via natural gas • Completed Meraux’s 20 MBPD capacity expansion in 4Q14; expect approximately $90 million annual EBITDA contribution at 2014 (1) prices on total investment of approx. $260 million • 30 MBPD total capacity addition at St. Charles and Port Arthur in progress; expect startup in 2H15 (1) 2014 based on Jan 1 through Dec 9 prices; see project details in Appendix

19 Ethanol Investments Performing Well Note: See Appendix for reconciliation of EBITDA to GAAP results. 2014 EBITDA through 3Q. Outstanding Cash Generation Excellent Acquisitions Competitive Advantages • 11 plants acquired between 2Q09 and 1Q14 for $794MM, less than 35% of replacement value • 1.3 billion gallons total annual production • Scale and location in corn belt • Operational best practices transferred from refining • Low capital investment • $2.1 billion cumulative EBITDA generated since acquisitions • $162 million cumulative capex excluding acquisition costs $2,058 $162 millions Cumulative Capex and EBITDA EBITDA Capex

20 Our Sponsored MLP Valero Energy Partners (NYSE: VLP) Growth-oriented logistics MLP with 100% fee-based revenues • Valero owns entire 2% general partner interest, all incentive distribution rights, and 68.6% LP interest • High-quality assets integrated with Valero’s refining system • Primary vehicle to grow Valero’s midstream investments • Provides access to lower cost capital • Completed first dropdown from Valero on July 1, 2014 Unlocking Asset Value

21 Significant Growth Opportunity with Estimated Inventory of Eligible MLP Assets EBITDA over $900 Million (1) Includes assets that have other joint venture or minority interests. Pipelines (1) Racks, Terminals, and Storage (1) Rail Marine (1) • 51 docks and two Panamax class vessels Fuels Marketing and Distribution We are also developing an accelerated drop-down strategy • Over 1,200 miles of active pipelines • Expect start-up of 440-mile Diamond Pipeline from Cushing to Memphis refinery in 1H17 • Over 72 million barrels of active shell capacity for crude and products • 139 truck rack bays • Three crude unloading facilities with estimated total capacity of 150 MBPD • Our 5,320 new CPC-1232 railcars can be used for long-term rail movements, such as ethanol and asphalt • Currently under evaluation as drop-down candidate

22 We Believe Valero Is an Excellent Investment • Majority of capacity located in U.S. Gulf Coast and Mid- Continent with access to cost-advantaged crude, natural gas, NGLs, and corn • Proven operations excellence • Excellent investment and operations in ethanol • Emphasis on capital allocation to stockholders • Disciplined capital investment that prioritizes higher-value, higher-growth, faster-payback opportunities to capture benefits of advantaged resources • Unlocking value through growth in MLP-able assets and dropdowns to VLP • Focus on valuation multiple expansion

23 Appendix Topic Pages Valero 2014 Highlights and 2015 Goals 24-25 Valero Energy Partners LP and CST Brands Spinoff 26-28 Capital Spending and Key Investment Details 29-38 Other Valero Operations Highlights 39-44 Macro Outlook and Key Margin Drivers 45-51 Global Demand and Refining Capacity 52-56 U.S. Fundamentals and DOE Data 58-68 International Fundamentals 69-70 Non-GAAP Reconciliations 71 IR Contact Information 72

24 Key 2014 Highlights Operations Excellence • Achieved record system refinery capacity utilization of approximately 96% in 2014 through 3Q • Increased consumption of price-advantaged North American light sweet crudes by 297 MBPD on average through 3Q14 compared to 2013 • Reduced Quebec refinery’s crude costs by $3/bbl versus Brent from premium of approximately $2.50/bbl in 2013 to discount of approximately $0.50/bbl in 2014 through 3Q • Secured attractively priced term-supply of WTI Midland for Mid-Continent refineries • Increased gasoline and distillate exports by 57 MBPD, or 18%, in 2014 through 3Q versus 2013 • Launched Top Tier gasoline in wholesale marketing system • Achieved record $664 million Ethanol segment EBITDA through 3Q14 Capital Returns to Stockholders • Increased cash returned to stockholders through dividends and buybacks by approximately $460 million, or 33%, versus 2013 Disciplined Capital Investments • Completed and started up Meraux hydrocracker conversion project in 4Q14 • Secured capital efficient Diamond Pipeline option and supply to Memphis refinery with crude from Cushing • Started up 90 MBPD of total crude rail unloading capacity at St. Charles and Port Arthur • Acquired idled ethanol plant in Mt. Vernon, Indiana at less than 15% of replacement cost and restarted facility within five months Unlocking Asset Value • Grew VLP via first drop-down acquisition of $154 million purchase price on July 1, 2014 Other • Diamond Green Diesel JV to benefit by estimated $130 million on retroactive reinstatement of biodiesel blending credit

25 Key 2015 Goals Operations Excellence • Start up Montreal crude terminal with startup of Enbridge Line 9B reversal and lower Quebec refinery’s crude costs versus Brent compared to 2014 • Grow product export market share and increase branded wholesale fuels volume Capital Returns to Stockholders • Increase total payout ratio of earnings over 2014’s level Disciplined Capital Investments • Complete Houston and Corpus Christi toppers on time and on budget • Make final investment decisions on methanol plant at St. Charles refinery and alkylation unit at Houston refinery; if approved, share strategic rationale with investors • Complete 25 MBPD McKee CDU capacity expansion • Complete 30 MBPD total hydrocracker capacity expansions at Port Arthur and St. Charles • Gain permit approval and construct Benicia crude rail unloading facility Unlocking Asset Value • Grow inventory of MLP-able EBITDA

Growth in Inventory of Estimated Eligible MLP EBITDA Fuels distribution would provide incremental EBITDA if selected $800 ($15) $24 $46 $54 $909 Dec. 2013 Guidance (with base + 2014- 2015 projects) Drop -Downs 2014 - 2015 Logistics Additional Projects Diamond Pipeline Current Guidance 2016 - 2019 Logistics Projects millions 26

27 VLP Nearing the “High Splits” • 3Q14 distribution at $0.24 per unit • Expect VLP to reach 25% split in 2015 and 50% split in 2016 based on existing growth guidance, but timing may change depending on evaluation of accelerated drop-down strategy Minimum quarterly First target Second target Third target Thereafter Target Quarterly Distribution per Unit Marginal Percentage Interest in Distributions Unitholders GP $0.2125 above $0.2125 up to $0.244375 above $0.244375 up to $0.265625 above $0.265625 up to $0.31875 $0.31875 98% 98% 85% 75% 50% 2% 2% 15% 50% 25%

CST Brands, Inc. (NYSE: CST) has traded at approximately double the earnings valuation of VLO VLO received nearly $1 billion in cash net of tax liability and working capital benefit to CST • Liquidated our 20% retained interest in CST common stock, or 15 million shares, in November 2013 CST Brands is now Valero’s largest wholesale customer 28 Unlocked Value via Retail Spinoff in 2013

Allocating Significant Growth Capital to Logistics 29 • Railcars spending declines as receipt of railcars order concludes • Future spending focuses on pipelines $510 $175 $45 $220 $180 $665 $170 $45 $5 $900 $400 $715 2014E 2015E 2016E millions Marine, Docks, and Other Logistics Pipelines and Tanks Railcars and Unloading

30 Refining & Renewables Capital Focused on Capturing Benefits of Key Long-Term Trends $345 $490 $180 $110 $30 $120 $150 $105 $45 $40 $115 $690 $790 $300 2014E 2015E 2016E millions Nat Gas & Petchems Other Projects Hydrocracking Advantaged Crude Processing $50 • Advantaged crude processing optimizes feedstock flexibility, mainly for light crudes • Hydrocracking increases production of high-margin distillates • Petchems, methanol, and hydrocracking upgrade natural gas or NGLs to higher-value liquids

McKee Diesel Recovery Improvement and CDU Expansion Startup Expected in 2H15 31 Incremental Volume (MBPD) Feeds WTI 25 Products LPG 0.4 Benzene concentrate 0.3 Gasoline 12 Jet - Diesel 12 Resid 0.6 Investment Highlights Status • Adding 25 MBPD crude unit capacity and parallel light ends processing train • Expect to improve yields and volume gain by recovering diesel from FCC and HCU feeds • Expect to increase diesel and gasoline production on price- advantaged crude • Expect to reduce energy consumption via heat integration • Diesel recovery and benefits started in mid-2014; Expect crude expansion start-up in 2H15 Project Estimates Total investment $140 MM Annual EBITDA contribution (1) $100 MM Unlevered IRR on total spend (1) 45% (1) Estimates based on 2014 prices through Dec 9; EBITDA = operating income before deduction for depreciation and amortization expense

Meraux Hydrocracker Conversion Completed December 2014 32 Incremental Volume (MBPD) Feeds Purchased hydrogen (MMSCFD) 13 Products (MBPD) Gasoline 5 Jet - Diesel 19 HSVGO 2 Unconverted gasoil (23) Fuel oil - Project Estimates Total investment $260 MM Annual EBITDA contribution (1) $90 MM Unlevered IRR on total spend (1) 25% Investment Highlights Status • Converted hydrotreater into high- pressure hydrocracker and repurposed old FCC gas plant for additional LPG recovery • Expect to upgrade 23 MBPD gasoil and low-cost hydrogen (via natural gas) mainly into high quality diesel • Expect to increase refinery distillate yield versus gasoline (Gas/Diesel ratio drops from 0.72 to 0.59) • Expect to increase refinery liquid volume yield by 1.8% • Avoided compliance capex on FCC • Project started up Dec-14 and operating well (1) Estimates based on 2014 prices through Dec 9; EBITDA = operating income before deduction for depreciation and amortization expense

Houston and Corpus Christi Crude Topping Units Expected Online in 1 st Half of 2016 33 Estimates Incremental Volume (MBPD) Feeds Eagle Ford crude 70 Low sulfur atmos resid (24) Products LPG 2.5 Propylene 0.9 BTX 0.4 Naphtha 16 Gasoline 7 Jet 16 Diesel 9 Resid (3) Project Estimates Total investment $350 MM Annual EBITDA contribution (1) $260 MM Unlevered IRR on total spend (1) 55% Estimates Incremental Volume (MBPD) Feeds Eagle Ford crude 90 Low sulfur atmos resid (29) Distillate (2) Butane (2) Hydrogen (MMSCFD) 3 Products LPG 0.8 Propylene 0.4 Naphtha 24 Gasoline 5 Jet 23 Diesel 4 Slurry 0.2 Project Estimates Total investment $400 MM Annual EBITDA contribution (1) $240 MM Unlevered IRR on total spend (1) 45% Corpus Christi Houston (1) Estimates based on 2014 prices through Dec 9; EBITDA = operating income before deduction for depreciation and amortization expense

Diamond Pipeline 34 Project Estimates Total investment (1) $484 MM Cumulative spend through 2014 Zero Annual EBITDA contribution (2) $46 MM Unlevered IRR on total spend at least 12% (1) Includes additional Valero cost for pipeline connection at Memphis refinery (2) EBITDA = Operating income before deduction for depreciation and amortization expense Investment Highlights • Increases Memphis refinery’s crude supply flexibility via connection to Cushing and economic crudes • Provides direct control over crude blend quality • Grows Valero’s inventory of assets eligible for VLP dropdown in capital- efficient manner • Valero holds option until January 2016 to acquire 50% interest in pipeline • Expect completion in 1H17 or earlier

Estimated Key Price Sensitivities on Project Economics 35 Change in Estimated EBITDA (1) Relative to 2014 (2) Prices ($millions/year) McKee Diesel Recovery & CDU Expansion Meraux HCU Expansion Corpus Christi Topper Houston Topper ICE Brent, +$1/bbl none $0.8 $0.4 none ICE Brent – WTI, +$1/bbl $5.5 none None none ICE Brent – LLS, +$1/bbl N/A none $25.6 $32.9 Group 3 CBOB – ICE Brent, +$1/bbl $2.0 N/A N/A N/A Group 3 ULSD – ICE Brent, +$1/bbl $5.5 N/A N/A N/A USGC CBOB – ICE Brent, +$1/bbl N/A $1.7 $2.4 $2.4 USGC ULSD – ICE Brent, +$1/bbl N/A $6.8 $9.0 $9.9 Natural gas (Houston Ship Channel), +$1/mmBtu -$0.7 -$1.9 -$4.3 -$3.2 Naphtha – ICE Brent, +$1/bbl N/A none $5.8 $8.8 LSVGO – ICE Brent, + $1/bbl N/A -$7.3 $3.1 $5.2 Total investment IRR, +10% cost -6% N/A -5% -4% (1) Operating income before deduction for depreciation and amortization expense (2) 2014 YTD through Dec 9 Note: Margin drivers shown are not inclusive of all feedstocks and products in economic models. Estimated economic sensitivities can not be accurately interpolated or extrapolated solely from the estimated key price sensitivities shown above. 1

Project Price Set Assumptions 36 Driver ($/bbl) 2014 (1) ICE Brent 99.51 ICE Brent – WTI 6.43 ICE Brent – LLS 2.64 USGC CBOB – ICE Brent 3.70 G3 CBOB – WTI 12.45 USGC ULSD – ICE Brent 14.45 G3 ULSD – WTI 24.00 Natural gas (Houston Ship Channel, $/mmBtu) 4.36 Naphtha – ICE Brent -2.12 LSVGO – ICE Brent 8.92 (1) 2014 = YTD through Dec 9

37 Port Arthur and St. Charles Hydrocrackers Performance Details Benefits Realized in Reported Results Trailing 4 Quarters $mm, except /bbl amounts 4Q12 3Q14 Increase Gulf Coast Capture Rate 58.8% 63.2% 4.4% x Gulf Coast Indicator/bbl, trailing 4Q 3Q14 $19 = Extra margin captured/bbl $0.83 x Gulf Coast volume, trailing 4Q 3Q14 MPBD 1,586 x Annualized Days 365 = Benefit from higher Capture Rate $483 Gulf Coast Throughput Volume MBPD 1,488 1,586 98 x Gulf Coast Indicator/bbl, trailing 4Q 3Q14 $19 x Gulf Coast Capture Rate, trailing 4Q 3Q14 63% x Annualized Days 365 = Benefit from higher Volume $429 Total Benefit from Hydrocracker Projects $912 Less: estimated operating costs before depreciation and amort. exp. -110 = EBITDA (estimated) $802 Key Assumptions • Market prices for trailing 4 quarters as of 3Q14 applied to guidance model disclosed by Valero in February 2012 to estimate $780 million in EBITDA • Gulf Coast capture rate increase based on average of trailing 4 quarters reported margin per barrel (excluding cost of RINs allocated in results at $0.30/bbl for 4Q12 and $0.40/bbl for 4Q13 averages) divided by Gulf Coast indicator margin • Gulf Coast LPGs pricing based on propane • Many factors can influence our reported margins including, but not limited to, charges, yields, pricing, timing and ratability, secondary costs, other allocations, hedging, and GAAP inventory costing methods • EBITDA = operating income before deduction for depreciation and amortization expense

Gated Investment Management Process • Development costs increase as project progresses through the phases • NPV and IRR of future cash flows per price forecasts and operating plans evaluated • “Target” IRR hurdle rate ranges, which can change depending on the project and market conditions: Refining growth projects, target >=50% in Phase 1 to >=30% in Phase 3 Cost savings projects, target >=12% in Phase 3 Logistics projects, target pre-tax >=12% in Phase 3 + refinery benefits 38 PHASE 2 Lead Case Development • Select lead case and define project objectives • Improve cost estimate to +/- 30% PHASE 3 Refinement • Define project scope and execution plans • Prepare decision support package for final decision • Narrow cost estimate to +/-10% PHASE 1 Opportunity Evaluation • Identify opportunities and alternatives • Develop business case • Generate cost estimate range of +100% to - 50% PHASE 4 Execution • Detail engineering, procurement, and initial construction • Develop start- up schedule APPROVED Startup and Evaluate • Post-audit back- casting • Capture lessons learned

39 Valero’s Light Crude Processing Capacity in North America MBPD (1) Not incentivized in 3Q14 to maximize North American light crude consumption versus alternative grades. • 25 MBPD additional capacity expected in 2H15 • Distillate recovery improvements • 90 MBPD capacity expected 1H16 • Displaces 30 MBPD intermediate feedstock purchases • 70 MBPD capacity expected 1H16 • Displaces 25 MBPD intermediate feedstock purchases (1) 1,010 1,210 1,395 3Q14 Actual Utilization Current Capacity Estimate Future Capacity (with Projects) McKee Crude Unit Expansion Corpus Christi Crude Topper Houston Crude Topper

40 Processing of Cost-Advantaged U.S. and Canadian Crude by Valero Continues to Grow Note: Non-U.S. and Canadian crude runs exclude Valero’s Pembroke Refinery. Cost-advantaged crudes exclude imports and historically discounted medium sour crudes, such as Mars/ASCI domestic; heavy sour crudes, such as Maya; and high-acid crudes, such as Pazflor. 0 200 400 600 800 1,000 1,200 1,400 1,600 0 200 400 600 800 1,000 1,200 2010 2011 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 MBPD MBPD Gulf Coast Mid-Con West Coast Quebec Non-U.S. & Canadian

41 Valero Leads Peers in Total Location- Advantaged Crude Capacity Source: Company 10-k reports. Crude distillation capacity based on geographic location. Access to lower cost North American crude benefits refiners in Mid-Continent, Gulf Coast, and Canada; product export opportunities for Gulf Coast and Canada 1,934 1,714 1,211 443 129 VLO MPC PSX HFC TSO MBPD Canada U.S. Gulf Coast U.S. Midcontinent

42 Expect Quebec City Refinery to Have Cost-Advantaged Access to 100% North American Crude Slate in 2015 Shifted to cost-advantaged crudes via rail and foreign flagged ships from USGC, with additional savings expected from deliveries on Enbridge Line 9B beginning in 1H15 0% 20% 40% 60% 80% 100% 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 Quebec City Refinery Crude Slate Foreign Imports North American

43 U.S. Natural Gas Provides Opex and Feedstock Cost Advantages Note: Estimated per barrel cost of 860,000 mmBtu/day of natural gas consumption at 94% refinery throughput capacity utilization, or 2.7 MMBPD. $1.3 billion higher pre-tax annual costs $2.5 billion higher pre-tax annual costs Valero’s refining operations consume approximately 860,000 mmBtu/day of natural gas, split almost equally between operating expense and cost of goods sold Significant annual pre-tax cost savings compared to refiners in Europe or Asia $4/mmBtu $1.27/bbl $8/mmBtu Europe $2.55/bbl $16/mmBtu $5.10/bbl $0 $1 $2 $3 $4 $5 $6 /bbl Natural Gas Cost Sensitivity for Valero’s Refineries Asian LNG

44 Valero’s Capacity for Additional Product Exports (1) YTD through September 30 Opportunities to expand U.S. Gulf Coast export capability for gasoline to 308 MBPD and diesel to 472 MBPD Export markets pull volume from U.S., enabling high refinery utilization and improved margins Supported by global refined products demand growth Logistics investments also support segregation (1) 255 412 0 100 200 300 400 500 600 700 2011 Actual 2012 Actual 2013 Actual Current Capacity Valero’s U.S. Product Exports (MBPD) Gasoline Diesel 2014 YTD

Long-Term Macro Market Expectations Global Outlook U.S. Economy and Petroleum Demand North American Resource Advantage International Export Markets • Economic activity and total petroleum demand increases • Transportation fuels demand grows • Refining capacity growth slows after 2015; utilization stabilizes then expected to increase • Refinery rationalization pressure continues in Europe, Japan, and Australia • Economic growth strengthens over next five years, which stimulates refined product demand • Diesel and jet fuel demand continues to strengthen • Gasoline demand continues to recover moderately • Natural gas production growth still attractive and development continues • Crude production is economic; growth continues, but may be tempered with lower prices • North American refiners maintain competitive advantage • Broad lifting of crude export ban not expected for several years, if ever • U.S. continues to be an advantaged net exporter of products • Atlantic Basin market continues to grow, with increasing demand from Latin America and Africa • U.S. Gulf Coast is strategically positioned with globally competitive assets 45

46 U.S. and Canadian Production Growth Provides Crude Cost Advantage to North American Refiners Source: EIA, Consultants, company announcements and Valero estimates; 2014 U.S. Crude imports as of Sep 2014 Production growth reduces imports Largest growth from U.S. shale crude and heavy Canadian crude 0 2 4 6 8 10 12 14 16 18 2010 2011 2012 2013 2014E 2015E 2020E MMBPD U.S. and Canadian Crude Production vs. U.S. Crude Imports U.S. Shale Crude Heavy Canadian Light Canadian/ Syncrude Other U.S. Non-Canadian U.S. Crude Imports

Estimated Crude Oil Transportation Costs to USEC Rail $12 to $15/bbl to St. James Rail $12/bbl to Cushing Rail $9/bbl Cushing to Houston Pipe $2 to $4/bbl Midland to Houston Pipe $4/bbl CC to Houston $1 to $2/bbl Houston to St. James $1 to $2 /bbl to West Coast Rail $13 to $15/bbl USGC to USEC U.S. Ship $5 to $7/bbl USGC to Canada Foreign Ship $2/bbl Alberta to Bakken $1 to $2/bbl Rail $9/bbl U.S. Ship $4 to $5/bbl Alberta to Eastern Canada Rail $11 to $12/bbl Bakken 47

48 Crude Oil Differentials Versus ICE Brent Source: Argus; 4Q14 through Dec 12. LLS prices are roll adjusted -30% -25% -15% -10% -5% 0% 5% 10% 15% 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 1Q14 2Q14 3Q14 4Q14 Maya Mars ANS WTI LLS -20%

49 Valero’s Regional Refinery Indicator Margins Source: Argus; 4Q14 through Dec 12 $5 $10 $15 $20 $25 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 1Q14 2Q14 3Q14 4Q14 $/bbl Midcontinent WTI Cracking West Coast ANS Medium Sour Coking North Atlantic Brent Cracking Gulf Coast Heavy Sour Coking

• Gulf Coast Indicator: (GC Colonial 85 CBOB A grade- LLS) x 60% + (GC ULSD 10ppm Colonial Pipeline prompt - LLS) x 40% + (LLS - Maya Formula Pricing) x 40% + (LLS - Mars Month 1) x 40% • Midcontinent Indicator: [(Group 3 CBOB prompt - WTI Month 1) x 60% + (Group 3 ULSD 10ppm prompt - WTI Month 1) x 40%] x 60% + [(GC Colonial 85 CBOB A grade prompt - LLS) x 60% + (GC ULSD 10ppm Colonial Pipeline - LLS) x 40%] x 40% • West Coast Indicator: (San Fran CARBOB Gasoline Month 1 - ANS USWC Month 1) x 60% + (San Fran EPA 10 ppm Diesel pipeline - ANS USWC Month 1) x 40% + 10% (ANS – West Coast High Sulfur Vacuum Gasoil cargo prompt) • North Atlantic Indicator: (NYH Conv 87 Gasoline Prompt – ICE Brent) x 50% + (NYH ULSD 15 ppm cargo prompt – ICE Brent) x 50% • LLS prices are Month 1, adjusted for complex roll • Prior to 2010, GC Colonial 85 CBOB is substituted for GC 87 Conventional • Prior to 4Q13, Group 3 Conventional 87 gasoline substituted for Group 3 CBOB 50 Valero’s Regional Indicator Margins Defined

51 Source: Argus & Bloomberg; 2014 YTD Japan LNG through Oct 31, U.S. & Europe through Dec 15; natural gas price converted to barrels using factor of 6.05x 0 20 40 60 80 100 120 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Brent and Natural Gas Prices Brent U.S. Europe Japan LNG • U.S. natural gas is significantly discounted to Brent on an energy equivalent basis • Prices expected to remain low and disconnected from global oil and gas markets for foreseeable future Low Cost U.S. Natural Gas Provides Competitive Advantage $/bbl $101 $97 $16/mmBtu $51 $8/mmBtu $26 $4/mmBtu

52 Global Petroleum Demand Projected to Grow Source: Consultant (EIA and IEA) and Valero estimates. Consultant annual estimates generally updated 6 to 12 months after year end. Emerging markets in Latin America, Middle East, Africa, and Asia lead demand growth -3.5 -2.5 -1.5 -0.5 0.5 1.5 2.5 3.5 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014E 2015E MMBPD World Petroleum Demand Growth Non-OECD OECD (excl. U.S.) U.S.

53 U.S. Refining Capacity Is Globally Competitive and Continues to Take Market Share Source: EIA and IEA (U.S. data through September 2014, Europe data through October 2014) Less-competitive capacity Source: EIA (2014 data through September) Net imports Net exports • U.S. flipped from importer to exporter on lower local product demand and higher refinery utilization, particularly in PADDS 2, 3, and 4, driven by structural cost advantages for crude oil and natural gas • Gulf Coast refineries have gained export market share in the Atlantic Basin -3.0 -2.5 -2.0 -1.5 -1.0 -0.5 0.0 0.5 1.0 1.5 2.0 1999 2001 2003 2005 2007 2009 2011 2013 MMBPD U.S. Net Product Imports Midcon 93% Gulf Coast 91% Rockies 91% West Coast 86% East Coast 82% Western Europe 77% PADD 2 PADD 3 PADD 4 PADD 5 PADD 1 OECD Europe Refinery Utilization by PADD Trailing 12-months

54 World Refinery Capacity Growth -0.2 0.2 0.6 1.0 1.4 1.8 2014 2015 2016 2017 2018 MMBPD Estimated Net Global Refinery Crude Distillation Additions China Middle East Other (incl. U.S. and Latin America) • New capacity additions expected in Asia and Middle East • Announced new capacity in Brazil, Mexico, and Colombia likely to be smaller and start later than planned • Expansions in Ecuador, Peru, Algeria, and Egypt unlikely due to cost and geopolitical pressures • Capacity rationalization expected to continue in Europe, Australia, and Japan Source: Consultant and Valero estimates; Net Global Refinery Additions = New Capacity + Restarts – Announced Closures

55 Capacity Rationalization in Atlantic Basin Sources: Industry and Consultant reports and Valero estimates • Marginal refiners in U.S. East Coast, Caribbean and Western Europe are shutting capacity • Demand growth, poor reliability, and low utilization in Latin American refineries provide opportunities for competitive refineries to export products and meet supply needs 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 MPBD Rest of World Atlantic Basin Annual Global CDU Capacity Closures 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 MBPD Cumulative Global CDU Capacity Closures Rest of World Atlantic Basin

*Partial closure of refinery captured in capacity. Note: This data represents refineries currently closed, ownership may choose to restart or sell listed refinery. Sources: Industry and Consultant reports and Valero estimates Location Owner CDU Capacity Closed (MBPD) Year Closed Location Owner CDU Capacity Closed (MBPD) Year Closed Perth Amboy, NJ Chevron 80 2008 St. Croix, U.S.V.I Hovensa 350 2012 Bakersfield,CA Big West 65 2008 Aruba Valero 235 2012 Westville, NJ Sunoco 145 2009 Rome, Italy TotalErg 82 2012 Bloomfield, NM Western 17 2009 Fawley, U.K.* ExxonMobil 80 2012 Teesside, UK Petroplus 117 2009 Trecate, Italy* ExxonMobil 70 2012 Gonfreville, France* Total 100 2009 Paramo, Czech Republic Unipetrol 20 2012 Dunkirk, France Total 140 2009 Lisichansk, Ukraine TNK-BP 175 2012 Japan* JX Holdings 110 2009 Paramount, CA Alon 90 2012 Toyama, Japan Nihonkai Oil 57 2009 Harburg, Germany Shell 107 2013 Ingolstadt, Germany* Bayernoil 102 2010 Port Reading, NJ Hess N/A 2013 Japan* JX Holdings 90 2010 Venice, Italy ENI 80 2013 Arpechim, Romania OMV 70 2010 Sakaide, Japan Cosmo Oil 140 2013 Odessa, Ukraine Lukoil 57 2010 Dartmouth, Canada Imperial Oil 88 2013 Montreal, Canada Shell 130 2010 Thessaloniki, Greece Hellenic Petroleum 83 2013 Yorktown, Virginia Western 65 2010 Tenerife, Canary Islands Cepsa 85 2013 Reichstett, France Petroplus 85 2010 Yokkaichi, Japan* Cosmo Oil 43 2014 Wilhemshaven, Germany Phillips 66 260 2010 Tokuyama, Japan Indemitsu Kosan 114 2014 Sodegaura, Japan Fuji Oil 50 2010 Japan Nippon 200 2014 Cremona, Italy Tamoil 94 2011 Kurnell, Australia Caltex 135 2014 St. Croix, U.S.V.I,* Hovensa 150 2011 Kawasaki, Japan Tonen- General 105 2014 Funshun, China PetroChina 70 2011 Mantova, Italy Mol 69 2014 Keihin Ohgimachi, Japan Toa Oil Company 120 2011 North Pole, AK Flint Hills 220 2014 Clyde, Australia Shell 75 2011 Muroran, Japan JX Holdings 180 2014 Marcus Hook, PA Sunoco 175 2011 Ellesmere Port, UK* Essar 55 2014 Berre, France LyondellBasell 105 2012 Milford Haven, UK Murphy 130 2014 Coryton, U.K. Petroplus 220 2012 Kaohsiung, Taiwan Chinese Petroleum Corp 200 2015 Petit Couronne, France Petroplus 160 2012 Bulwer Island, Australia BP 102 2015 56 Global Refining Capacity Rationalization

Location Owner CDU Capacity (MBPD) Lytton, Australia Caltex 109 Nishihara, Japan Petrobras/Sumitomo 95 Inchon, Korea SK Energy 270 Whitegate, Ireland Phillips 66 71 Barbers Point, HI Chevron 54 Come-By-Chance, Canada North Atlantic Refining 115 Pasadena, TX Petrobras 100 Bahia Blanca, Argentina Petrobras 31 Gothenburg, Sweden Shell 80 Livorno ENI 106 Taranto ENI 120 Mazeikiai, Lithuania PKN 190 Okinawa, Japan Petrobras/Nansei Sekiyu 100 Falconara, Italy API 80 Hamburg, Germany Tamoil 78 Collombey, Switzerland Tamoil 72 Chiba, Japan Cosmo Oil 240 Chiba, Japan TonenGeneral 152 57 Global Refining Capacity For Sale or Under Strategic Review Sources: Direct and public disclosure by each owner

58 U.S. Crude Fundamentals Source: DOE weekly data through December 5, 2014 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000 55,000 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Cushing Crude Inventory (MB) 5 Yr High 5 Yr Low 2012 140,000 150,000 160,000 170,000 180,000 190,000 200,000 210,000 220,000 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec PADD 3 Crude Inventory (MB) 320,000 330,000 340,000 350,000 360,000 370,000 380,000 390,000 400,000 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec U.S. Crude Inventory (MB) 5 Yr High 5 Yr Low 2012 2013 2014 5 Yr Avg 5 Yr High 5 Yr Low 2012

59 U.S. Gasoline Fundamentals USGC Brent Gasoline Crack (per bbl) U.S. Gasoline Demand (mmbpd) U.S. Net Imports of Gasoline and Blendstocks (mbpd) U.S. Gasoline Days of Supply 22 23 24 25 26 27 28 29 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 5 yr high 5 yr low 2014 2013 5 year avg -400 -200 0 200 400 600 800 1000 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 5 year avg 5 yr high 5 yr low 2014 2013 -$15 -$10 -$5 $0 $5 $10 $15 $20 $25 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 5 yr high 5 yr low 2013 2014 5 year avg 8.2 8.4 8.6 8.8 9.0 9.2 9.4 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 5 yr high 5 yr low 2014 2013 5 year avg Source: Argus; 2014 weekly data through Dec 12 Source: 2014 DOE monthly data through Sep; weekly data through Dec 5 Source: 2014 DOE monthly data through Sep; weekly data through Dec 5 Source: 2014 DOE monthly data through Sep; weekly data through Dec 5

60 U.S. Distillate Fundamentals USGC Brent ULSD Crack (per bbl) U.S. Distillate Demand (mmbpd) Source: Argus; 2014 data through Dec 12 Source: 2014 DOE monthly data through Sep; weekly data through Dec 5 Source: 2014 DOE monthly data through Sep; weekly data through Dec 5 Source: 2014 DOE monthly data through Sep; weekly data through Dec 5 U.S. Distillate Days of Supply U.S. Distillate Net Imports (mbpd) $0 $5 $10 $15 $20 $25 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 5 yr high 5 yr low 2013 2014 5 year avg 3.2 3.4 3.6 3.8 4 4.2 4.4 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 5 yr high 5 yr low 2014 2013 5 year avg 25 30 35 40 45 50 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 5 yr high 5 yr low 2014 2013 5 year avg -1300 -1100 -900 -700 -500 -300 -100 100 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 5 yr low 5 yr high 2014 2013 5 year avg

61 U.S. Transport Indicators

62 U.S. Transport Indicators: Trucking

63 Increase in U.S. Gasoline Exports 0 100 200 300 400 500 600 700 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Other Europe Other Latin America Mexico Canada Latest 4 Wk avg estimate (Finished only) 12 Month Moving Average, MBPD Note: Gasoline represents all finished gasoline plus all blendstocks (including ethanol, MTBE, and other oxygenates) Source: DOE Petroleum Supply Monthly data as of September 2014. 4 Week Average estimate from Weekly Petroleum Statistics Report and Valero estimates.

64 Decrease in U.S. Gasoline Imports 0 200 400 600 800 1000 1200 1400 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Other Europe Other Latin America Canada Latest 4 Wk avg estimate (Fin+Blendstock) 12 Month Moving Average, MBPD Note: Gasoline represents all finished gasoline plus all blendstocks (including ethanol, MTBE, and other oxygenates) Source: DOE Petroleum Supply Monthly data as of September 2014. 4 Week Average estimate from Weekly Petroleum Statistics Report and Valero estimates.

Source: DOE Petroleum Supply Monthly with data as of September 2014. 4 Week Average estimate from Weekly Petroleum Statistics Report 65 Increase in U.S. Diesel Exports 12 Month Moving Average, MBPD 0 200 400 600 800 1000 1200 1400 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Other Europe Other Latin America Mexico Canada Latest 4 Wk avg estimate

66 U.S. Is Net Refined Products Exporter U.S. Demand for Refined Products and Net Trade MMBPD U.S. Petroleum Demand Excluding Ethanol and Non-Refinery NGL’s (Refined Product Demand) Net Imports Net Exports Implied Total Production of U.S. Refined Products Implied Production of U.S. Refined Products for Domestic Use Valero’s share of U.S. exports has averaged 20% to 25% over the past few years 14 15 16 17 18 19 20 21 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 Note: Implied production = Petroleum demand excluding ethanol and non-refinery NGLs minus product net imports. Source: EIA, Consultant and Valero estimates; data through Sep 2014

67 U.S. Shifted to Net Exporter • Net refined products exports increased from 335 MBPD in 2010 to 2,426 MBPD in 2014 • Diesel net exports averaged 917 MBPD in 2014 (Jan-Sep) • Gasoline net imports averaged -31 MBPD in 2014 (Jan – Sep) • Gasoline and blendstocks have shifted to net exports -3,000 -2,500 -2,000 -1,500 -1,000 -500 0 500 1,000 1,500 2,000 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 Other Diesel Gasoline Total Note: Gasoline represents all finished gasoline plus all blendstocks (including ethanol, MTBE, and other oxygenates) Source: DOE Petroleum Supply Monthly data as of Sep 2014 MBPD

68 U.S. Growing Market Share by Exports • Refined products demand is growing in developing countries and Atlantic Basin (capacity closures) • U.S. Gulf Coast (PADD III) is the largest source of exported products U. S. Product Exports By Destination U. S. Product Exports By Source 12 Month Moving Average 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 2014 MMBPD PADD V PADD I PADD II PADD III (Gulf Coast) 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Other Europe Latin America Canada MMBPD Source: DOE Petroleum Supply Monthly data as of Sep 2014; Latin America includes South and Central America plus Mexico.

Mexico Statistics Diesel Gross Imports (MBPD) Gasoline Gross Imports (MBPD) Crude Unit Throughput (MBPD) Crude Unit Utilization 69 200 250 300 350 400 450 500 550 2007 2008 2009 2010 2011 2012 2013 2014 60% 65% 70% 75% 80% 85% 90% 2007 2008 2009 2010 2011 2012 2013 2014 950 1,000 1,050 1,100 1,150 1,200 1,250 1,300 1,350 2007 2008 2009 2010 2011 2012 2013 2014 0 20 40 60 80 100 120 140 160 180 200 2007 2008 2009 2010 2011 2012 2013 2014 Source: PEMEX, latest data Oct 2014

70 Decrease in Venezuelan Exports to the U.S. Source: EIA, September 2014 0 50 100 150 200 250 300 350 MBPD Total Products Gasoline and Gasoline Blending Components Diesel

71 Reconciliation of Operating Income to EBITDA Ethanol (millions) 2Q09 – 4Q09 2010 2011 2012 2013 2014* Cumulative Operating income $165 $209 $396 $(47) $491 $628 $1,842 + Depreciation and amortization expense $18 $36 $39 $42 $45 $36 $216 = EBITDA $183 $245 $435 $(5) $536 $664 $2,058 *2014 Ethanol earnings through September 30

Investor Relations Contacts 72 For more information, please contact: John Locke Executive Director, Investor Relations 210-345-3077 john.locke@valero.com Karen Ngo Manager, Investor Relations 210-345-4574 karen.ngo@valero.com